An enhanced geothermal system (EGS) generates geothermal electricity without the need for natural convective hydrothermal resources. Until recently, geothermal power systems have exploited only resources where naturally occurring heat, water, and rock permeability are sufficient to allow energy extraction.[1] However, by far most of geothermal energy within reach of conventional techniques is in dry and impermeable rock.[2] EGS technologies enhance and/or create geothermal resources in this hot dry rock (HDR) through 'hydraulic stimulation'.

When natural cracks and pores do not allow economic flow rates, the permeability can be enhanced by pumping high-pressure cold water down an injection well into the rock. The injection increases the fluid pressure in the naturally fractured rock, mobilizing shear events that enhance the system's permeability. As there is a continuous circulation, neither is a high permeability required, nor are hydraulic fracturing proppants required to maintain the fractures in an open state. This process is termed hydro-shearing,[3] perhaps to differentiate it from hydraulic tensile fracturing, used in the oil and gas industry, which blasts through rock instead of simply revealing natural fractures.[4]

Water travels through fractures in the rock, capturing the rock's heat until forced out of a second borehole as very hot water. The water's heat is converted into electricity using either a steam turbine or a binary power plant system.[5] All of the water, now cooled, is injected back into the ground to heat up again in a closed loop.

EGS technologies, like hydrothermal, geothermal can function as baseload resources that produce power 24 hours a day, like a fossil fuel plant. Unlike hydrothermal, EGS appears to be feasible anywhere in the world, depending on the economic limits of drill depth. Good locations are over deep granite covered by a 3–5 kilometres (1.9–3.1 mi) layer of insulating sediments that slow heat loss.[6] EGS wells are expected to have a useful life of 20 to 30 years before the outflow temperature drops about 10 c (18 f) and the well becomes uneconomic.

"There are some technical difficulties and challenges there, but those people who are keen on getting Australia into geothermal say we've got this great access to resource and one of the things, interestingly, that's held them back is not having the capacity to put the drilling plants in place. And so what we intend this $50 million to go towards is to provide one-for-one dollars. Match $1 from us, $1 from the industry so that they can get these drilling rigs on to site and really get the best sites identified and get the industry going."[8]

The EU's EGS R&D project at Soultz-sous-Forêts, France, has recently connected its 1.5 MW demonstration plant to the grid. The Soultz project has explored the connection of multiple stimulated zones and the performance of triplet well configurations (1 injector/2 producers).[9]

The Portuguese government awarded, in December 2008, an exclusive license to Geovita Ltd to prospect and explore geothermal energy in one of the best areas in continental Portugal. An area of about 500 square kilometers is being studied by Geovita together with the Earth Sciences department of the University of Coimbra's Science and Technology faculty, and the installation of an Enhanced Geothermal System (EGS) is foreseen.

Cornwall is set to host a 3MW demonstration project, based at the Eden Project, that could pave the way for a series of 50-MW commercial-scale geothermal power stations in suitable areas across the country.[10][11]

A commercial-scale project near Redruth is also planned. The plant, which has been granted planning permission,[12] would generate 10 MW of electricity and 55 MW of thermal energy and is scheduled to become operational in 2013–2014.[13][14]

The United States pioneered the first EGS effort — then termed Hot Dry Rock — at Fenton Hill, New Mexico with a project run by the federal Los Alamos Laboratory.[15] It was the first attempt anywhere to make a deep, full-scale HDR reservoir, and efforts there spanned 1974 through 1992, in two phases. The Lab described its efforts thusly: " The world's first HDR reservoir was completed at Fenton Hill in 1977 at a depth of about 2.6 km (8,500 feet), with rock temperatures of 185 C. This so-called Phase I system was enlarged in 1979 by additional hydraulic stimulation and was operated successfully for about 1 year to test the feasibility of the heat extraction concept and to measure the thermal and hydraulic performance of the reservoir. Overall, the results of the Phase I testing were very positive, clearly demonstrating that heat could be extracted at reasonable rates from a hydraulically stimulated region of low-permeability hot crystalline rock without serious technical or environmental problems... To extend HDR technology to the higher temperatures and heat production rates required to support a commercial-sized electric generating plant, the development of a larger and hotter HDR reservoir was initiated at Fenton Hill... In March and April of 1986, the new Phase II reservoir was prepared for initial hydraulic circulation and heat extraction testing... A 30-day flow test,referred to as the Initial Closed-Loop Flow Test, was started on 19 May 1986 and was completed on 18 June 1986... With a constant reinjection temperature of 20 C, the production temperature steadily increased to about 190 C, corresponding to a thermal power level of about 10 MWt. No thermal drawdown was observed. Furthermore... geothermometers indicated in situ reservoir temperatures of about 242 and 222 C, respectively... consistent with an initial measured rock temperature of 232 C at an average reservoir depth of 3,550 m." After listing eight major accomplishments of its HDR program, the Lab wrote: "The main technical task remaining involves the enlargement of the two-well HDR reservoir concept to meet commercial power production requirements. Although this is not a trivial task, field efforts at Fenton Hill... have demonstrated it requires only the logical extension of established oil and gas reservoir development technology. Therefore, HDR development does not require the technical "quantum jumps" that will be necessary before other new power technologies become commercial. If reservoir stimulation can be achieved as systematically as envisioned, then this last technical hurdle of creating and testing a commercial-sized system at Fenton Hill is well within reach during the next 5 years." Unfortunately, however, th Los Alamos scientists never got to take this final step to commercial HDR/EGS, as the budget for Fenton Hill was zeroed-out by the Department of Energy early in the Clinton Administration** and a subsequent Los Alamos "Request for Proposals" designed to bring in private geothermal companies to accomplish the work was withdrawn by Washington.

Working at the edges—using EGS technology to improve hydrothermal resources[edit]

EGS funding languished for the next few years, and by the next decade, US efforts focused on the less ambitious goal of improving the productivity of existing hydrothermal resources. According to the fiscal year 2004 Budget Request to Congress from DOE's Office of Energy Efficiency and Renewable Energy, [16]

EGS are engineered reservoirs that have been created to extract heat from economically unproductive geothermal resources. EGS technology includes those methods and equipment that enhance the removal of energy from a resource by increasing the productivity of the reservoir. Better productivity may result from improving the reservoir’s natural permeability and/or providing additional fluids to transport heat.[17]

In fiscal year 2002, this vision translated into completing "preliminary designs for five competitively selected projects employing EGS technology," and the selection of one project for "full-scale development" at the Coso Hot Springs geothermal field at the US Naval Weapons Air Station in China Lake, California, and two additional projects for "preliminary analysis from a new solicitation" at Desert Peak in Nevada and Glass Mountain in California. Funding for this effort totaled $1.5 million. [18]

In fiscal year 2003, $3.5 million was appropriated to launch the Coso project, with the aim of improving the permeability of an existing poorly performing well, and to complete the conceptual design and feasibility studies at the Desert Peak and Glass Mountain sites.[19]

The fiscal year 2004 request for $6 million was to "[s]tep up work on EGS cost-shared projects' at the three sites, to include "drilling and reservoir stimulation experiments" at one and drilling a production well at another.[19]

The DOE followed up with another FOA on March 27, 2009, of stimulus funding from the American Reinvestment and Recovery Act for $350 million, including $80 million aimed specifically at EGS projects,[21]

Some induced seismicity is inevitable and expected in EGS, which involves pumping fluids at pressure to enhance or create permeability through the use of hydro-shearing techniques. In contrast to induction of tensile failure (the purpose of hydraulic fracturing used in the oil and gas industries), EGS seeks to induce relatively small shear failure of the rock's existing joint set to create an optimum reservoir for the transfer of heat from the rock to the water in order to produce steam.[22][23] Seismicity events at the Geysers geothermal field in California have been strongly correlated with injection data.[24]

The case of induced seismicity in Basel merits special mention; it led the city (which is a partner) to suspend the project and conduct a seismic hazard evaluation, which resulted in the cancellation of the project in December 2009.[25]

Risks associated with "hydrofracturing induced seismicity are low compared to that of natural earthquakes, and can be reduced by careful management and monitoring" and "should not be regarded as an impediment to further development of the Hot Rock geothermal energy resource".[26]

The recently established Center for Geothermal Energy Excellence at the University of Queensland has been awarded AUD 18.3 million for EGS research, a large portion of which will be used to develop CO2 EGS technologies.

Research conducted at Los Alamos National Laboratories and Lawrence Berkeley National Laboratories examined the use of supercritical CO2, instead of water, as the geothermal working fluid, with favorable results. CO2 has numerous advantages for EGS:

A 2006 report by MIT,[27] and funded by the U.S. Department of Energy, conducted the most comprehensive analysis to date on the potential and technical status of EGS. The 18-member panel, chaired by Professor Jefferson Tester of MIT, reached several significant conclusions:

Resource size: The report calculated the United States total EGS resources from 3–10 km of depth to be over 13,000 zettajoules, of which over 200 ZJ would be extractable, with the potential to increase this to over 2,000 ZJ with technology improvements — sufficient to provide all the world's current energy needs for several millennia.[27] The report found that total geothermal resources, including hydrothermal and geo-pressured resources, to equal 14,000 ZJ — or roughly 140,000 times the total U.S. annual primary energy use in 2005.

Development potential: With a modest R&D investment of $1 billion over 15 years (or the cost of one coal power plant), the report estimated that 100 GWe (gigawatts of electricity) or more could be installed by 2050 in the United States. The report further found that "recoverable" resources (accessible with today's technology) were between 1.2–12.2 TW for the conservative and moderate recovery scenarios respectively.

Cost: The report found that EGS could be capable of producing electricity for as low as 3.9 cents/kWh. EGS costs were found to be sensitive to four main factors: